IR 05000155/1988006
| ML20154R257 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 05/16/1988 |
| From: | Fresco A, Gardner R, Parkinson K, Ulie J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20154R252 | List: |
| References | |
| 50-155-88-06, 50-155-88-6, NUDOCS 8806070250 | |
| Download: ML20154R257 (34) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-155/88006(ORS)
Docket No. 50-155 License No. OPR-06 Licensee:
Consumers Power Company
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212 West Michigan Avenue l
Jackson, Michigan 49201
Facility Name:
Big Rock Point Nuclear Plant Inspection At:
Charlevoix, Michigan Inspection Conducted:
March 21-25, and May 3, 1988
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5 - I G-W Inspectors:
oseph M. Ulie Date 5~Ib 5 h
e Date.
s-1643 e h ar s
Date h.
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Approved By:
Ronald N. Gardner, Chief 5'Ib-88 l- _
Plant Systems Section Date Inspection Summary
. Inspection on March 21-25, and May 3, 1988 (Report No. 50-155/88006(DRS))
f Areas Inspected:
Special, announced inspection of licensee action on
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previous inspection findings and a selective assessment of licensee compliance with Sections III.G. and L. of Appendix R relative to a review of NRC granted exemption requests (30703, 64100, 64704, 92701 and 92702).
Results:
Of the areas inspected, no violations or deviations were identified.
8806070250 880518 PDR ADOCK 05000155 o
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DETAILS 1.
Persons Contacted
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Big Rock Point
- B. Alexander, Technical Engineer
- P. Donnelly, Nuclear Assurance Administrator
- T. Dugan, Property Protection Operations Supervisor
- T. Elward, Plant Manager E. Evans, Senior Engineer D. Herboldscheimed, Outage Coordinator
- R. Hill, Nuclear Assurance
- G. Petitjean, Planning / Administrative Superintendent
- R. Schrader, Electrical / Instrumentation and Control Engineering Supervisor
- D Swem, Senior Engineer
- B. Trubilowicz, Operations Supervisor
- G. Withrow, Engineering and Maintenance Superintendent
- J. Wood Jr., Section Head - Asset Protection Consumers Power Company
- E. Dorbeck, Staff Engineer
- D. Smedley, Staff Engineer, Nuclear Licensing
- Denotes those persons present at the exit interview of March 25, 1988.
The inspectors also contacted other licensee personnel during the course of this inspection.
2.
Action on Previous Inspection Findings a.
(Closed) Open Item (155/85022-01):
The pre-fire plans lacked detail in describing items located in the area, such as type of fire extinguishant available (best suited for fire attack), radiation hazards, and type and location of vital equipment for safe shutdown.
The inspector reviewed selected plant area and zone pre-fire plans contained in Appendix E of the "Summary of Fire Protection Provisions" document (FPPSD) dated February 27, 1987, and determined sufficient detail now exists to satisfy closure of this item.
The inspector made mention that this revision of the fire pre plans was generally well-written having useful information readily available, b.
(Closed) Open Item (155/85022-02):
A concern was raised that fire brigade members need to respond to the fire scene with appropriate protective clothing.
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The inspector requested and was provided documentation regarding the last three annual offsite fire department fire drill exercises held at the plant.
These three exercises were held on August 12, 1987; August 20, 1986; and August 22, 1985.
Each of these exercises i
documented the use of fire brigade member response with protective clothing.
Based on the above, the licensee appears to be adequately responding to fire scenes with protective clothing.
Although this record review indicated in practice that brigade members were responding to fire scenes with protective clothing, a review of the fire response procedure gave the appearance that two brigade members referred to as "initial responders" may opt, dependent upon the brigade leaders direction, to report directly to the fire scene.
The inspector informed the licensee that adherence to recognized firefighting response practices and to NRC requirements should be emphasized to the fire brigade members.
c.
(0 pen) Violation (155/85022-03):
The licensee failed to request an exemption from the requirements of Section III.G.2. of Appendix R after determining that the fire protection features in the Screenwell and Pumphouse did not meet the specific requirements of Section III.G.2., in that no fire suppression system was installed.
Subsequently, by letter dated July 1, 1986, the licensee filed an exemption request.
However, upon further licensee review, a more desirable method to achieve and maintain hot shutdown was determined which resulted in a revised exemption request dated October 14, 1986.
This method does not rely on any of the equipment in the Screenhouse and is considered a more conservative method.
However, this method involves the temporary attachment of a hose to maintain hot shutdown.
This action is considered a repair by Appendix R guidelines; therefore, an exemption is still viewed as appropriate.
During this inspection, the inspectors reviewed the pending exemption correspondence and toured the plant areas where the hose connections would need to be made.
The inspectors provided the following comments regarding the October 14, 1986 licensee exemption request:
(1) The Standby Diesel Generator should be identified as the power source for the Demineralized Water System (DWS) pump.
It should also identify that additional fuel from off-site sources may be required to meet the postulated 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> loss of off-site power conditions.
(2) The statement that the flow path from the OWS pump to the Emergency Condenser (EC) is opened by operating an air-operated valve should be corrected to indicate that two valves must be opened.
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t (3) The statement th'at analyses have been performed to show that when the DWS.is connected to the instrument air compressor cooling system, as described in the exemption request, there would be enough cooling water'available onsite to permit the EC to operate for a minimum of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> should be qualified by mentioning that this time was arrived at by taking credit for the average of operator log readings for other tanks onsite.
There are minimum levels set by Administrative Procedures but no Technical Specification requirements exist for any tank levels.
This. item will remain open pending NRR determination of the acceptability of the licensee's October 14, 1986 submittal.
d.
(Closed) Open Item (155/85022-05): 'The licensee's analysis did not appear to consider the affects of localized heat-transfer on vital equipment.
The analysis did r.ot demonstrate that a lube oil fire would be contained and would not affect safe shutdown equipment or involve any of the other recirculation pump lube oil supply.
These concerns were raised during inspector review to determine licensee compliance with an approved exemption.
By letter dated July 1, 1986, the licensee provided a response to NRC concerns regarding the previously issued exemption to Section III.0 of Appendix R requiring an oil collection systom to-be installed on the recirculation pumps.
After a review of the information provided in the July 1, 1986 letter, the NRC staff, by letter dated January 16, 1987, found that the conclusions reached in the original exemption for tne oil collection system still remain valid.
Consequently, no further
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licensee action is deemed appropriate at this time, and this item is considered closed.
e.
(Closed) Open Item (155/85022-07):
The fire detection and fire suppression systems for the reactor recirculation pump room area were not installed in accordance with National Fire Protection Association Codes (NFPA).
The licensee, by letter dated July 1,1986, provided a response to NRC concerns regarding the previously issued exemption for the reactor recirculation pump room area.
By letter dated January 16, 1987, the NRC determined that the conclusions reached in the original exemption still remain valid.
In addition, the cover letter for Generic Letter (G.L. ) 86-10, dated April 24, 1986, states that where the licensee chooses not to seek prior NRC review and approval, an evaluation must be performed by a fire protection engineer and retained for future NRC audit.
Section 5, "Automatic Detection and Suppression," of Enclosure 1, "Interpretations of Appendix R," of G.L. 86-10 states that to comply with the Rule provisions, suppression and detection
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sufficient to protect against the hazards of the area must be installed.
It further states that detection and suppression providing less than full area coverage may be adequate to comply with the regulation.
- Where full area suppression and detection is not installed, licensees must perform an evaluation to assess the adequacy of partial suppression and detection to protect against the hazards in the area.
Utilizing the above clarifications approved by the
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Commission, a review of the appropriate areas of Appendix C of the licensee's FPPSD, dated February 27, 1987, was conducted.
The licensee's fire protection engineer performed an engineering analysis of the fire detection and fire suppression systems for the reactor coolant pump area.
Due to radiological ALARA concerns, the inspectors were unable to
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physically tour the reactor coolant pump area but were provided other descriptive information (i.e. photos of the area)
from the licensee's' staff.
After an inspector review of specific room conditions (i.e. room HVAC characteristics, detector suitability to in-situ hazards, and fire gases / heat behavior patterns), and after a review of the engineering analysis ulong with additional other discussions with the licensee's fire protection staff, it was concluaed that the installed fire systems did not entirely meet the specific wording of the NFPA codes.
However, this critical equipment area was provided fire detection system and fire suppression system coverage as required by the NRC to meet Appendix R.
Additionally, certain design criteria of the recirculation pump area sprinkler system was submitted by the licensee by letter dated August 31, 1979, and was determined to be acceptable by NRC letter dated December 17, 1979.
During this inspection (March 1988), the inspector also confirmed that procedures (Numbered ALP 1.6, Revision 142, dated September 1, 1987) do exist for the activation of the fire suppression system protecting the recirculation pumps.
Consequently, no further licensee action is deemed appropriate at this time, and this item is considered closed.
During the inspectors review, the licensee acknowledged an error in the August 31, 1979 submittal (Item 3.1.23) regarding the installation of heat collectors on the recirculation pump room sprinkler system spray nozzles.
These heat collectors are not installed.
However, as discussed in Inspection Report 155/85022, even the adequacy of non-approved heat collectors is considered questionable.
An additional error of the August 31, 1979 submittal was noted, in that in lieu of a "lock" switch, a non-locking flip switch control was provided in the control room to actuate the
recirculation sprinkler system deluge valve.
At the March 25, 1988
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exit meeting, the licensee was requested to correct the docketed l
record.
This request was acknowledged by licensee management.
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(0 pen) Open Item (155/85022-08):
Fire detectors were not installed throughout containment as per NFPA codes.
Nor was an arrangement of fire detectors throughout containment observed that would provide prompt detection of incipient fires.
On September 28, 1982, the licensee requested an exemption from having to install a fixed fire. suppression system (excluding the recirculation pump room) inside containment.
Additionally, the licensee described the fire detection systems installed in specific locations within containment.
These locations included the core spray pump room-(actually located in a separate room outside containment), control rod drive accumulator area, shutdown heat exchanger room, and the interior cable spreading area.
The NRC granted this exemption by letter dated March 8, 1983, in a Safety Evaluation Report (SER).
The wording used in the l
SER specified that several modifications had been made inside containment to allow rapid fire detection action, that the installed early warning detection system would provide prompt detection of incipient fire conditions, and that fire hoses were distributed throughout containment.
With regard to the granted exemptions, the inspector determined that the installed early warning detection system that would provide the referenced prompt detection was accurately detailed in the licensee submittal.
To determine the adequacy of the installed detection system, the inspectors reviewed all historical correspondence between the licensee and NRC which provided a description of the fire detection system for containment.
The licensee's submittals included the July 14, 1978, December 8, 1978, and August 31, 1979 letters.
These letters provided NRC requested information and formed the licensing basis for NRC to determine that the as-installed fire detection systems satisfied the criteria in Appendix A to NRC Branch Technical Position 9.5-1.
The NRC transmittals accepting this design and providing background information were dated November 20, 1978 (requast for information only), April 4, 1979, and December 17, 1979.
More recently, the licensee has performed engineering analyses to meet G.L. 86-10 guidelines so as to justify Appendix R compliance for the installed system configurations.
A review of this analyses, together with either a visual inspection of the accessible installed detection systens or a review of drawings for systens that weren't accessible resulted in the inspector concluding that these systems met NRC requirements.
Therefore, this portion of the item is considered closed.
Further, as part of this review, the inspectors, during plant tours, verified that the accumulation of transient combustibles inside containment is being properly maintained, as described in the approved exemptions dated March 8,1983 and March 26, 1985.
This control of combustibles is considered an improvement since the previous Appendix R inspection.
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However, since this item pertains to detectors on a contaiiment-wide basis, and this review dealt with the adequacy of the as-installed systems and Appendix R,Section III.G.3 locations within containment, this item will remain open pending further review of other containment areas to determine if these areas meet NRC requirements.
(Refer to Paragraph 7.d and e for further details).
On March 24, 1988, an additional discrepancy was identified in containment.
As described by the licensee, location
"Containment-South of Reactor," also identified as Fire Area 11, Zone B, is designated a III.G.3. location.
Section III.G.3.
requires a fire detection and suppression system be installed in the zone under consideration.
An approved exemption was granted for containment providing relief from the installation of a fire suppression system (excluding the recirculation pump room) by NRC letter dated March 8, 1983.
This exemption did not exempt the need for a fire detection system.
I According to the licensee's description, this zone starts at the interior cable penetration room (Fire Area 11, Zone A) which has fire detection and extends around the east and north sides of the fuel pool structure which lacks a ' ire detection system.
By visual inspection the inspectors identified that Zone B did not have a fire detection system installed.
The licensee's FPPSD identifies that safe shutdown capability after a worst case fire in this area could still be attained by using the EC and the Shutdown Cooling System.
The inspector's review determined that alternate shutdown capability does exist.
With this alternate method available, fire damage could occur to equipment in this location; however, one train of systems fr9e of fire damage would still be available to achieve and maintain hot shutdown conditions from the Auxiliary Shutdown Building (ASB).
Therefore, while the safe shutdown capability of Section III.G.1 was met, the fire protection features had not been satisfied, in that Fire Area 11, Zone B lacked a fire detection system.
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exemption had been requested for this zone but a G.L. 86-10 type
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analysis had been performed for this location.
The inspectors raised a concern regarding the acceptability of the analysis in satisfying Section III.G of the Appendix R criteria.
As a result, this item is considered an unresolved item (155/88006-01) pending licensee resolution with NRR.
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g.
(Closed) Open Item (155/85022-09):
The licensee was requested to provide a valid engineering analysis for the location of the detectors in the condensate pump room.
As previously discussed, the cover letter for G.L. 86-10, dated April 24, 1986, specifies that where the licensee chooses not to seek prior NRC review and approval, an evaluation must be performed by a fire protection engineer and retained for future NRC audit.
In addition, as was also previously discussed, Section 5 of Enclosure 1 of G.L. 86-10 indicates that to comply with the
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t Appendix R Rule provisions, suppression and detection sufficient to protect against the hazards of the area must be installed.
It further states that detection and suppression providing less than full area coverage may be adequate to comply with the regulation.
Where full area suppression and detection is not installed, licensees must perform an evaluation to assess the adequacy of partial suppression and detection to protect against the hazards in the area.
Utilizing the above clarifications approved by the Commission, the inspectors reviewed the appropriate areas of Appendix C of the licensee's FPPSD, dated February 27, 1987.
The licensee's staff fire protection engineer performed an engineering analysis for the location of the detectors in the condensate pump room.
During the inspection, the inspectors conducted in plant walkthroughs of this area.
The inspectors concluded that the lack of a fire detector in the middle bay did not meet the specific wording of the NFPA code but that the critical equipment in the room was provided fire detecticn coverage as required by the NRC to meet Appendix R by having installed fire detectors in the end bays.
In addition, other room conditions (i.e. room HVAC characteristics, behavior of products of combustion travel, and detector suitability to the in-situ hazards) were considered in this review.
As part of this review, licensee compliance with the NRC granted exemption, dated March 20, 1984, was verified as discussed above.
Based on that review, the inspector concluded that alternative shutdown capability was orovided independent of the condensate pump room.
The alternate shutdown method / capability for the condensate pump room requires manual operation of the control rod drive pump suction valves within this room.
The licensee determined that the combustible loading of this room is considered low, and that the required manual actions would not be required until after 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> following the fire.
The available recovery time, before performance of the manual actions within this room, were determined to be acceptable.
Also, during additional reviews of the March 20, 1984 granted exemption, the inspectors concluded that alternative shutdown capability was also provided independent of the turbine generator building.
The previous Appendix R inspection (1985/1986) did not identify any other concerns relative to the condensate pump room or turbine generator building.
Therefore, the review to confirm licensee compliance with the approved exemption dated March 20, 1984, is considered complete at this time.
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(Closed) Open Item (155/85022-10):
The inspectors observed that the three fire detectors located in the rear of the control room were placed behind return air ducts which raised the concern of a delay in response time of these detectors.
In Appendix C of.the licensee's FPPSD, dated February 27, 1987, an analysis of the control room fire detection system was provided.
The inspector's review of the licensee's G.L. 86-10 engineering analysis concluded that the in place fire detectors were satisfactory and met NRC requirements.
The above fire detection system design concern was raised during inspector review of the licensee's September 28, 1982 exemption request for relief from the Section III.G.3 requirement for a fixed fire suppression system inside the control room fire area.
Since resolution of the above open item has been achieved and since the previous Appendix R inspection did not identify any other concerns relative to the control room exemption request, the review to confirm licensee compliance with this portion of the approved exemption, dated March 8, 1983, is considered complete at this time.
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(0 pen) Open Item (155/85022-11):
As a result of Appendix R modifications and the upgrading of certain fire protection features which were detailed in the licensee's fire protection program evaluation document, dated March 29, 1977, the inspectors requested the licensee to update this document so as to reflect the present plant fire protection features.
In addition, the licensee committed to providing a comprehensive FPPSD, as described in the licensee's April 14, 1986, transmittal.
By letter dated February 27, 1987, the licenste submitted a FPPSD providing a more detailed up to date description of the fire protection and safe shutdown features of the plant.
However, as a result of the inspectors review, certain fire protection feature discrepancies were identified, and a more detailed electrical analysis section relative to Appendix R is still needed.
Therefore, further revision of this document is required.
The inspectors provided the licensee's staff with examples of identified discrepancies (e.g.,Section I, Fire Area 15 (Machine Shop); Paragraph 8 - specifies that all walls are rated at 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />; however, according to the July 14, 1978 licensee letter, the east wall is rated at two hours) which the licensee acknowledged.
The licensee indicated that plans were being made to correct and improve the FPPSD in the areas mentioned.
This item will remain open pending further review of the licensee's actions to correct the discrepancies and improve the FPPSD.
The inspector's evaluation of the FPPSD was a partial review.
Further review of the entire FPPSD by the NRC for the purpose of determining its acceptability may occur in the future.
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3.
Background Information According to an NRC letter to the licensee, dated November 24, 1980, the provisions of Appendix R that are applicable to the fire protection features of Big Rock Point are Sections III.G, Fire Protection of Safe Shutdown Capability, III.J, Emergency Lighting, and III.0, Oil Collection System (s) for the Reactor Coolant Pump (s).
The letter further stated that these three Sections were required to be backfitted in their entirety by the new rule, regardless of whether or not alternatives to the Specific requirements of these Sections had been previously approved
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by the NRC staff.
The letter also indicated that the fire protection features of Big Rock Point must satisfy the specific requirements of Sections III.G, J, and 0 of Appendix R, unless an exemption from the Appendix R requirements was approved by the Commission.
Subsequently, in licensee submittals dated March 19, April 1, May 19, and September 24, 1981, and February 25, April 30, and July 9, 1982 (originally requested seven exemptions), the licensee provided additional information in support of the final six requested exemptions, which were proposed in final form in a submittal dated September 28, 1982 (withdrew one of the original seven exemptions).
By NRC letter dated March 8, 1983, five of the six exemption requests were granted.
The exemption request which was denied was identified as Item 5 of the licensee's September 28, 1982 submittal regarding a scheduler exemption request which was determined not to be necessary.
In addition, the NRC letter dated March 8, 1983, identified the NRC review of the licensee's alternate shutdown capability as required by Sections III.G.3 and III.L of Appendix R to 10 CFR Part 50 to be complete.
During the previous (initial) Appendix R inspection, certain concerns were raised regarding the approved 5 exemptions.
This inspection in part was intended to follow-up on those concerns, and to continue the review of other granted exemptions.
Further, in the licensee's letter dated March 19, 1981, the licensee stated that the plant will meet Sections III.J and III.0 of Appendix R. Exemptions from the technical requirements of these sections were not initially requested.
However, by letter dated February 9, 1982, and as corrected by letter dated February 11, 1982, the licensee requested an exemption from Section III.0 based upon further evaluation.
By letter dated April 5, 1982, the NRC granted this exemption.
Yet, during the Appendix R inspection (1985/1986) concerns were raised regarding the licensee's analysis that led to the NRC's granting of the exemption.
By letter dated July 1,1986, the licensee, af ter performing further review, submitted a more detailed analysis in support of the exemption.
Consequently, by letter dated January 16, 1987, the NRC determined that the conclusions reached in the original exemption for the oil collection system remained valid, sased on the above, the licensee was considered to be in corepliance with Sect'on III.0 of Appendix R.
Therefore, this area was not reviewed t. / ig this inspection.
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Further, during the previous Appendix R inspection, two concerns were raised regarding Section III.J, Emergency Lighting, as follows:
(1) a violation was issued regarding the licensee's failure to take timely action in correcting emergency lighting system deficiencies within the power block areas; and (2) a lack of emergency lighting in the plant yard areas was identified.
The licensee subsequently resolved each of these concerns.
Resolution of the first concern was_ documented in Inspection Report 155/86011.
Resolution of the second concern occurred when the licensee received an approved exemptien by NRC letter dated' February 17, 1987.
A revised FPPSD was submitted for NRC review in February 1987 (see Paragraph 2.i for further details).
During this inspection, the inspectors utilized this updated document to determine licensee compliance in the selected areas reviewed.
However, this inspection was not intended to be a complete review of the entire updated document.
The insp tors review in determining licensee compliance with the applicab k sections of Appendix R within the FPPSD included the review of analysis allowed by G.L. 86-10.
4.
Systems Required for Safe Shutdown Appendix A of the FPPSD provides a listing of the equipment required
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for safe shutdown assuming a loss of offsite power.
For the two diverse methods of shutdown without the feedwater and main condenser the following equipment is listed:
Emergency Condenser Method Emergency Condenser (EC) Outlet Valves, M0-7053 and M0-7063
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Main Steam Isolation Valve, M0-7050 (MSIV)
Firewater Makeup Valve to Emergency Condenser, SV-4947 Firewater Makeup Flow Switch ECS Shell Level Switch Alternate Shutdown Battery Control Rod Drive (CRD) Pumps Diesel Fire Pump (DFP)
Emergency Diesel Generator (EDG)
Shutdown Cooling system (SCS) Pumps Reactor Cooling Water (RCW) Pumps Service Water System (SWS) Pumps Steam Drum level and Pressure Indication Miscellaneous Equipment Used for Variations of ECS Method Demineralized Water Pump (utilized for a Screenhouse Fire)
Air Compressor (utilized for a Screenhouse Fire)
Normal Makeup Valves to Emergency Condenser, CV-4028 and CV-4105 (utilized for a Screenhouse Fire)
Standby Diesel Generator (SDG) (utilized for a Screenhouse Fire)
Main Steam Isolation Backup Valves (Reactor Pressure Vessel (RPV)
Inventory / Pressure Control)
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RDS/ Core Spray Method
Reactor Depressurization System (RDS)
Core Spray (CS) Valves (not including Containment spray Valves),
M0-7051 and M0-7061 or M0-7070 and M0-7071 Electric and Diesel Fire Pumps Station Battery Core Spray Pumps Firewater to Core Spray Heat Exchanger (CSHX) Valve, M0-70ES or M0-7080 Reactor, Steam Drum, and Containment Level Indication Motor Control Centers, MCC 1A, 2A, and 2B Emergency Diesel Generator (EDG)
Of the above systems, the RDS, CS and Post-Incident Cooling Systems are redundant to the EC, Condensate Storage Tank and Demineralized Water Tank for Hot Shutdown.
The CS System water supply originates from the Fire System.
The CS Pumps take suction only from suction strainers inside the Containment Sump, and are therefore used only during the Recirculation Mode.
The initial core spray is provided by the Fire Pumps.
Since under some fire scenarios the Fire Pumps may be used to provide make-up water to the EC shell side, the Fire Pumps play an unusually important role in achieving Hot Shutdown, particularly because they are not normally part of the reactor cooling systems at most other nuclear power plants.
For each fire area or zone, both of which are Appendix R,Section III.G.2 and III.G.3 categories, the specific variations of the two methods, ECS and RDS/CS are described in Appendix B, "Post Fire Safe Shutdown Methods," of the FPPSD.
a.
Reactivity Control Insertion of the control rods provides the required reactivity control.
This can be accomplished by depressing the scram button in the Control Room.
Loss of offsite power also causes the reactor to trip.
In the event that offsite power is not lost, the reactor can be tripped by throwing the breakers for the Control Rod Drive Pumps.
b.
Reactor Coolant Inventory Control When using the EC, make-up for cooldown shrinkage and technical specification allowable leakage is provided by the Control Rod Drive Pumps which can be supplied from the Condensate Storage Tank.
The licensee has proviaed a calculation to the NRC to show that at a 25 F/hr cooldown rate, 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> are available before makeup to the Reactor Coolant system is required.
In the event that the Control Rod Drive Pumps are unavailable, the plant can be cooled down to primary coolant system (PCS) pressure of 300 psig within the 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> and the Shutdown Cooling System (SDC) put into operation.
This would
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preclude the need to provide makee9.
Alternatively, a cooldown rate could be effected which reduces primary system pressure to 100 psig to allow use of low pressure make-up provided by the Fire System Pumps through the Core Spray Valves.
The plant would remain in Hot Shutdown in this case.
When the RDS is used (in the manual mode), inventory control is also provided by the fire system pumps through the CS Valves until the CS pumps can be used in the recirculation mode, c.
Decay Heat Removal The basic methods of decay heat removal aside from the main condenser are the EC and the RDS which is coupled with the Fire Water System (FWS) and the CS System.
When using the EC, at least one of the two tube side motor-operated isolation valves must be opened and throttled to allow and control flow of Reactor Coolant vapor through the EC.
The water on the shell side of the EC is allowed to boil off and is discharged to atmosphere through a high stack.
The normal source of water is the DWS with the FWS as a backup.
The RDS is the redundant means of decay heat removal when the main condenser is available.
The RD5 valves are set for automatic actuation when the Reactor Low Level point is reached or they can be manually actuated from the Control Room.
There are four valves, each of which discharges into the Reactor Enclosure. The CS valves are opened.
The pressure is reduced to the 100 psig, the point at which the FWS pumps can provide water to the CS ring, the CS nozzle and the CS heat exchanger.
There are two FWS pumps.
One is electric but is powered by the EDG while the other is diesel powered.
Once conditions allow, the CS pumps are run from the EDG to provide CS Recirculation Cooling.
The fire pumps then supply the shell side of the CSHX to cool the water recirculated from the containment sump by the CS pumps.
The RDS is not the preferred method of shutdown because it discharges primary coolant to the containment atmosphere which would require extensive cleanup, results in a rapid depressurization of the reactor vessel, and injects non-condensate grade water into the reactor core and pressure vessel.
d.
Process Monitoring The following controls or instrumentation are required:
(1) EC Shutdown Method Controls for ECS Outlet Valves, M0-7053 and M0-7063
Controls for Main Steam Isolation Valve, M0-7050
Controls for FWS Makeup Valve to Emergency Condenser,
SV-4947
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Flow Switch - Firewater Makeup
Level Switch - EC Shell Side
Level / Pressure Indicators - Steam Drum (2) Variation of EC Shutdown Method Controls for Normal Makeup Valves to the EC, CV-4028 and
CV-4105 Controls for Main Steam Isolation Backup Valves
(3) RDS/CS Method Controls for CS Valves, M0-7051 and M0-7061 or M0-7070 and
M0-7071 Controls for Firewater to CSHX Valves, M0-7066 or MO-7080
Controls for RDS Valves Level Indicatcrs - Reactor Vessel, Steam Drum, Containment
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Hot Shutdown Support Systems To maintain hot shutdown using the ECS method, the following support systems are required:
AC power from the Emergency or Standby Diesel Cenerators
DC power from the 125V station batteries
Demineralized Water system
Other sources such as the Condensate Storage Tank (CST), the
Condenser Hotwell, and several waste receiver tanks Fire Water system
Since the RDS/CS method involves rapid depressurization, the reactor vessel quickly reaches cold shutdown conditions (300 psig) so that maintenance of hot shutdown is not appropriate, f.
Cold Shutdown In the ECS method, cold shutdown can be initiated when the reactor pressure is below 300 psig.
The following equipment is required:
Shutdown Cooling Water pumps, heat exchangers, and flowpaths
Reactor Cooling Water pumps, heat exchangers, and flowpaths
Service Water pumps and flowpaths l
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In the RDS method, cold shutdown is meintained by the following equipment:
CS pumps and heat exchangers
Fire pumps supplying water to the Core Spray HX shell side
Containment Sump Recirculation flowpath
Level indication for reactor vessel, steam drum, and
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Alternate Shutdown Capability A fire in the following areas requires the use of the ASB facilities:
Control Room (Fire Area 1)
Exterior Cable Penetration Area (Fire Area 4)
Containment Interior Electrical Penetration Area (Fire Area 11,
Zone 1)
Containment - South of Reactor (Fire Area 11, Zone B)
Condensate Pump Room (Fire Area 2)
Electrical Equipment Room (Fire Area 5)
Turbine Generator Building (Fire Area 6)
Heating Boiler Room (Fire Area 14)
The following minimum required safe shutdown components can be controlled from the ASB:
Emergency Condenser Outlet Valve, M07053-
Emergency Condenser Outlet Valve, M07063
Main Steam Isolation Valve, M07050
Emergency Condenser Make-up Valve, SV4947 from the Fire Water
System The control circuits for these components are effectively isolated from the Control room.
The Fire Water Make-up Valve SV4947 is an upgrade since the March 8, 1983 SER was issued.
The Station EDG (DG11) is used for the Alternative Safe Shutdown System onsite power source.
A transfer switch (TRS-1401) was installed in the
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EDG (DG11) room to effect the transfer of EDG power from the normal Class IE buses to the Alternative Safe Shutdown System.
480V AC emergency power is transmitted through a disconnect swi ch (DISC 1441)
t to a power distribution box (TB 334) and then to another transfer switch (TRS-1442) for Control Rod Drive Pump #2, both of which are locatad just outside the equipment lock.
The 125V DC power that is needed for the operation of the EC Outlet, the Main Steam Isolation and EC Makeup Valves, and the instrumentation and indicating lights is obtained from a 50 cell station battery located in the ASB.
The cabling for the entire system is routed in conduits which are run separately from the normal Class IE circuits and do not pass through any common fire areas.
The instrumentation is independent of the Control Room, Cable Spreading Room, Electrical Equipment Room, Exterior Cable Penetration Area and Turbine Generator Building.
The 125V DC control power for the EDG (DG 11) is supplied through a circuit breaker which i
is considered to be an isolation device.
The capability to monitor the following parameters has been provided in the ASB:
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Steam Drum level, LI-3188
Steam Drum Pressure, PI-188
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Indicating lights are used to monitor the EC Level and the fire water makeup to the EC.
During the 1985-1986 inspection, the licensee was asked to prc"ide the sizing calculations and test results for the station battery located in the ASB.
A check of the' load profile, battery sizing calculations, and battery performance test data indicated that adequate battery capacity existed to support operation of the DC equipment for the required duration following a postulated fire concurrent with a loss of offsite power.
6.
Plant Walkthrough On March 24, 1988, a general walkthrough of licensee designated Appendix R,Section III.G.2 and III.G.3 plant areas was conducted including verification of licensee conformance with previously granted NRC exemptions.
These exemptions were described in NRC letters dated March 8, 1983, March 24, 1984, and two letters dated March 26, 1985.
(See Paragraph 11 for further plant exemption review).
Specific plant areas where inspector concerns were raised as a result of the walkthrough are discussed below and in Paragraph 2 of the report.
As described by the licensee, the "Service Building - Third Floor Offices" (Technical Support Center), is referred to as Fire Area 12, Zone C, and is designated as a III.G.2 location.
Section III.G.2 of Appendix R specifies that where reJundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same fire area, one of the following means of ensuring that one of the redundant trains is free of fire damage shall be provided:
a.
Separation of cables and equipment and associated non-safety circuits of redundant trains by a fire barrier having a 3-hour rating; or b.
Separation of cables and equipment and associated non-safety circuits of redundant trains by a horizontal distance of more than 20 feet with no intervening combustible or fire hazards.
In addition, fire detectors and an automatic fire suppression system shall be installed in the fire area; or c.
Enclosure of cable and equipment and associated non-safety circuits of one redundant train in a fire barrier having a 1-hour rating.
In addition, fire detectors and an automatic fire suppression system shall be installed in the fire area.
In addition,Section III.G.3 of Apptndix R specifies a fourth alternative that may be implemented oatside of primary containment as follows:
Installation of alternatire or dedicated shutdown capability independent of the equipmene, cabling and associated circuits under consideration, and installation of fire detection and fixed fire suppression systems in the area under consideration.
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for the redundant EC. 0utlet Valves, M0-7053 and M0-7063.
The inspectors i
confirmed that control cable C01-C02/97 for the Emergency Condenser Outlet Valve, M0-7053, and control cable C01-C02/98 for the EC Outlet-Valve, M0-7063, are routed in a common enclosure (conduit P064) through the Fire Area / Zone.
This' location is required to meet one of the above means of protection or have been granted an approved exemption.
The licensee's FPPSD identifies that safe shutdown capability, after a worst case fire in this area, could still be attained by using the EC and the Shutdown Cooling System.
The inspectors determined that alternate shutdown capability did exist.
With this alternate method available., fire damage could occur to the equipment in this location while maintaining the capability to have one train of systems available to achieve and maintain hot shutdown conditions from the ASB free of fire damage.
Therefore, the safe shutdown capability of Section III.G.1 was met.
However, the fire protection features had not been satisfied in that this zone lacked fire detection and fire suppressicq systems.
Additionally, the fire barrier between Fire Area 12, Zone C and Fire Area 1 (Control Room), did not provide the required fire barrier protection.
Nor has an exemption been requested.
However, in accordance with G.L. 86-10, the licensee performed an engineering analysis for this location.
The inspectors raised a concern regarding the acceptability of this overall analysis in satisfying Section III.G of the Appendix R criteria.
As a result, this item is considered an unresolved item (155/88006-02) pending licensee resolution with NRR.
An additional concern raised during the walkthrough regarded the
"Computer Room," Fire Area 13 which contains equipment, sensor and actuation cabinets, and cabling for the redundant trains of the RDS and which is required to meet one of the previous means of protection.
During the walkthrough the inspectors confirmed that the Section III.G.2 or III.G.3 fire protection features provided are the installation of a fire detection system and a fire barrier wall rated for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
According to the FPPSD, safe shutdown can still be obtained using the ECS and shutdown cooling system if a fire were to damage any of the equipment within the area.
The inspectors determined that alternate shutdown capability does exist.
With this alternate method available, fire damage could occur to equipment in this location however one train of systems free of fire damage would still be available to achieve and maintain hot shutdown conditions from the ASB.
Therefore, the safe shutdown capability of Section III.G.1 was met.
However, the fire protection features had not been satisfied in that this zone lacked a fire suppression system.
Further, the fire barrier
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between Fire Area 13 and Fire Area 5 (Electrical Equipment Room), which requires alternate shutdown capability, is considered to be rated for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> instead of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
An exemption had not been requested.
However, in accordance with G.L. 86-10, the licensee performed an engineering analysis for this location.
The inspectors raised a concern which focused on the acceptability of the fire barrier between Fire Area 13 and Fire Area 5 in satisfying Section III.G of the Appendix R criteria.
As a result, this item is considered an unresolved item (155/88006-03) pending licensee resolution with NRR.
7.
Post-Fire Procedure Review There are several variations of the two basic methods of shutdown, ECS and RDS/CS, that are utilized depending on the location of the fire and the equipment which must be assumed lost as a result.
These methods are described in Appendix B of the FFPSD.
The areas and zones which require alternate shutdown, and hence comply with Appendix R,Section III.G.3, are all addressed _by emergency procedure EMP 3.10.
This procedure is entered into by means of Volume 3, ALP-1,6, "Edwards and Pyrotronics Fire System Annunciator Tabulation," which directs the operators' responses to a fire detection alarm signal.
Emergency procedure ALP-1.6 also directs the response to fires in some of the areas which are intended to comply with Section III.G.2 of Appendix R, which do not require alternate shutdown.
Several of these areas either were not reviewed and do not have fire detection or have been exempted from fixed detection (refer to Paragraph 2.f), causing a potential difficulty for the operators to recognize that an abnormal condition has occurred and assure that a safe reactor shutdown can be achieved.
This inspection review was limited to the post-fire procedural aspects of Appendix R.
For the various shutdown methods in the FPPSD these areas were reviewed to determine if adequate procedures were in effect to address the Appendix R post-fire safe shutdown scenarios.
The basic categories of the methods described in Appendix B of the FPPSD area were as follows:
a.
Method I - Emergency Condenser Method This is the alternate shutdown method and was covered by Emergency Procedure EMP-3.10.
There are three procedures which are utilized to achieve safe shutdown from the ASB.
Emergency Operating Procedure EMP-3.10 is the primary procedure which references portions of System Operating Procedure 50P 5 for the Reactor Shutdown System and S0P 28 for Station Power.
EMP-3.10 can be entered into through ALP-1.6 by actuation of the fire system annunciators.
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Since a procedural walkdown had been conducted during the December 9-13, 1985 inspection, and there were no significant changes to the procedure since that time which would affect the walkdown, no walkdown was conducted during this inspection.
A concern which arose during the procedure walkdown conducted during the December 1985 inspection was the amount of time available to open the EC outlet valves after h reactor scram.
Although a reactor scram is the only operator action permitted from the Control Room without an exemption, as discussed in G.L. 86-10, the licensee's procedure assumes that the operator both scrams the reactor and opens the EC outlet valves from the Control Room.
The EC valves can also be opened from the ASB which can be reached in about five minutes from the Control room.
The licensee could not adequately demonstrate
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how long it would take before the Steam Drum Safety Valve setpoint would be reached with EC outlet valves closed and the reactor scrammed.
However, following a May 8, 1986, meeting at the plant site, the inspectors reviewed and accepted the licensee's analysis and conclusions that there are as little as three minutes available with EC outlet valves closed and the reactor scrammed before the first safety valve would lift.
Since containment entry is no longer required for any hot shutdown actions involving the ASB, this issue was considered resolved.
However, during this inspection, it was noted that one or more cycles of a safety relief valve (SRV) opening could occur before an EC outlet valve could be opened, assuming a 10-minute allowable time to reach the ASB, and that there are several actions to achieve cold shutdown in EMP-3.10 requiring containment entry before the end of the 72-hour loss of offsite power period.
The licensee did not have an analysis specifically to show that containment temperature and radioactivity levels are acceptable for entry under these postulated Appendix R conditions.
This is considered an open item (155/88006-04)
pending licensee action to resolve the above concern.
In addition, a review of the existing version of EMP-3.10 resulted in the following comments:
(1) The figure of 25 GPM mentioned in Step 1.5.3(e) as the rate at which the Condensate Storage Tank level is dropping to confirm that a CRD pump is running should be supplemented by the corresponding reading in percent / unit of time since the actual CST gauge reads in percent capacity.
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(2) Step 1.5.5 should mention that a Fire Pump must be started to continue ECS shell side make-up.
(3) Cross references were made to 50P-28 and SOP-5.
However, only EMP-3.10 is stored in the ASB.
These other procedures, plus relevant process and instrumentation diagrams (P& ids),
particularly for transferring water from other tanks into the DWS tank, should be stored in the ASB.
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f The above procedural comments are considered an example of open item (155/88006-05a) pending licensee action to resolve the above procedural ccmments.
b.
Method II - RDS/ Core Spray Method This method is applicable to Fire Area 7, Alternate Shutdown Building, Fire Zone 11N, Containment-Alternate Shutdown Penetration, and Fire Zone 21G, Outside Area-Alternate Shutdown Penetration.
All of these locations nave fire detection alarms ~and are covered by ALP 1.6.
The actual implementation of the RDS/ Core Spray method is covered by EMP 3.3, "Loss of Reactor Coolant," and also 50P-28,
"Station Power." No discrepancies were noted during this method review.
c.
Method III - Fire In Screenhouse Since a severe screen house fire could possibly damage all of the pumps needed to provide makeup water to the plant, including all sources of fire water, service water, and well water, the licensee developed a special segment of Procedure EMP-3.10 to deal with the situation.
However, alternate shutdown is not required.
A review of EMP-3.10, Appendix IV, "Severe Screen House Fire,"
indicated that the necessary procedural instructions were provided with the following exceptions:
(1) A step should be added directing the operator's attention to ensuring PCS makeup capability, i.e., operation of the CRD pumps and monitoring reactor level.
(2) The storage location of the hose in tiie Instrument Air Compressor Room and the specific hose connections in the Heating Boiler Room, Machine Shop, and the Instrument Air Compressor Room, as described in the October 14, 1986 exemption request, should be mentioned in the procedure as the intended locations for the hose connections with operator discretion used to determine other suitable connections.
(3) The Standby Diesel Generator should be mentioned as the intended power source for the Demineralized Water Pump in the event of concurrent loss of off-site power.
Pending revision of EMP-3.10 to address the above concerns, this is an example of an open item (155/88006-05b).
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Method IV/V Fires In Containment It was determined that for fires in Zones 11K - Control Rod Drive Pump Room, 11F - Shutdown Heat Exchanger room, and 11J - Reactor Cooling Water Pump Room the licensee currently has no operating procedures for loss of Primary Coolant System make-up capability where both CR0 pumpe are lost.
This is particularly important where no automatic fire detection is provided for zones inside containment.
In Generic Letter 86-10, Enclosure 2, Appendix R Questions and Answers, in response to Question 5.2.3 on the acceptability of developing post-fire operating procedures only for those areas where alternative shutdown is required, the NRC stated that "... For other areas of the plant, shutdown would be achieved utilizing one of the two normal trains of shutdown systems.
Shutdown in degraded modes (one train unavailable) should be covered by present operator training and abnormal and emergency operating procedures.
If the-degraded modes of operation are not presently covered, we would suggest that the operation staff of the plant determine whether additional training or procedures are needed."
Based on the foregoing, the licensee was requested to consider the need for emergency procedures covering loss of PCS make-up capability.
The licensee response was that such an emergency procedure was currently in draft form, but was not presented to the audit team.
Pending either issuance of such a procedure or formal review by the Plant Review Committee (PRC), this is an example of an open item (155/88006-05c).
e.
Method V - Normal Shutdown on Loss of Off-site Power This method covers those areas where the FPPSD states that shutdown could be achieved using the ECS method for a normal loss of offsite power condition.
Certain of these areas do not have automatic detection and may contain safe shutdown equipment.
It was recommended that the licensee present the issue of the need for additional procedures or training to safely respond to fires in the above areas to the PRC for a formal resolution.
Where off-site power remains available and where it does not should be considered.
This is considered an example of an open item (155/88006-05d) in conjunction with the item identified above concerning the lack of
a procedure for PCS make-up capability for fires inside containment.
f.
Method VI - Fire in the Emergency Diesel Generator Room For a fire in this area (Fire Area 10), the EC method is used with the diesel fire pump supplying make-up water, if off-site power is lost, to the EC shell side to maintain hot shutdown conditions.
The FWS is used to cool the RCW heat exchanger to achieve cold shutdown.
i The Standby Diesel Generator would be used to supply power to the RCW and SDC systems.
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Since automatic fire detectors are installed in this room, no problems concerning entry into procedures were noted.
The fuel supply for the diesel fire pump was shown by calculation to be 6.5 days.
However, procedure S0P-28, "Station Power," does not mention the Shutdown Cooling Water Pumps as a potential load for either the Standby Diesel Generator or the Emergency Diesel Generator (Step 6.3.1-17), although the Reactor Cooling Water pumps are mentioned. These are also only used for cold shutdown.
A calculation was provided to show that a SDCW pump motor could be added to the total reqtired loads for either generator.
Pending revision of S0P-28 to add the reference to the SDCW pump, this remains an example of an open item (155/88006-05e).
8.
Training The inspectors performed a review to determine the adequacy of instructor lesson plans pertaining to Appendix R related changes in emergency and operating procedures since October 1985.
All were satisfactory.
In particular, BTE-10 dated April 15, 1987, for "Fire in Turbine / Service Building or Exterior or Interior Cable Penetration Areas, and the Use of Safe Shutdown Equipment," was found to be a very comprehensive review of EMP-3.10.
The attendance sheets for those lessons were traced for two individuals:
a Control Operator No. 2, and a Shift Supervison.
The records indicated that both had attended the training courses for those lessons with one exception.
No record could be found to indicate that the Shift Supervisor had attended BWP-07 training on procedural changes.
The Control Operator received his training on December 4, 1987.
Until the involved Shift Supervisor makes-up the missed BWP-0/ training, this will be considered an open item (155/88006-06).
9.
Protection for Associated Circuits
Common Bus Concern Spurious Signals Concern
Common Enclosure Concern i
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Common Bus Concern The common bus associated circuit concern is found in circuits, j
either non safety-related or safety-related, where there is a common power source with shutdown equipment and the power source is not l
electrically protected from the circuit of concern.
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The common bus concern is made up of the following items:
Circuit Coordination Circuit Breaker / Protective Relay Testing and Maintenance (
High Impedance Fault Analysis
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i Following review of the above items, the licensee's protection for the associated circuit common bus concern was found to be satisfactory.
(1) Circuit Coordination Breaker Coordination is audited by reviewing the time current curves developed during the licensee's bus coordination study.
The following circuits were selected for review:
Circuit Comment 480 VAC MCC 1A C0 ORDINATION SATISFACTORY 480 VAC MCC 2B'
C0 ORDINATION SATISFACTORY 480 VAC MCC 2B TIE BREAKERS C0 ORDINATION SATISFACTORY 125 VDC PANEL 20 C0 ORDINATION SATISFACTORY 120 VAC PANEL 2Y COORDINATION SATISFACTORY Circuit breaker coordination was found to be satisfactory.
Control of fuse r mlacement is required to ensure maintenance of coordination for circuits protected by fuses.
The licensee's procedure number 3.2.1, Revision 4, Maintenance Order Processing, requires component replacement by "identical kind" or "Functional Equivalent Substitution." Functional equivalent substitution components must be documented by an engineering analysis worksheet.
The following randomly selected circuits were inspected to verify that the proper fuses were installed.
Circu,it Name Fuse Location Required Fuse Installed Fuse CRD Pump 1 TB334 BUSS LPS-RK70 BUSS LPS-RK70 Battery Fused DISC-1612 BUSS LPS-RK70 BUSS LPS-RK70 Disconnect Switch Main Alternate DISC-1441 BUSS LPS-RK300 BUSS LPS-RK300 Shutdown Fused Disconnect Switch M0-7053 Control MO-7053 Motor Bussman FRN-R5 Bussman FRN-R5 Power Starter M0-7050 Control M0-7050 Motor Bussman FRN-R5 Bussman FRN-R5 Power Starter The licensee's control of fuses was found to be satisfactory.
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In the event that coordination of safe shutdown power
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supplies is lost from either fire induced or non-fire induced
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failure (s), the licensee has provided procedural guidance (0NP-2.36, Revision 118, Loss Of Station Power and EMP-3.1, Revision 56, Loss of DC Power System) to strip bus / panel loads and reenergize only loads needed to achieve safe shutdown.
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To ensure that the existing satisfactory circuit coordination
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is not compromised by future design changes, the licensee has
an established procedure for modification design review, which
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includes reviewing for Appendix R concerns.
The licensee's circuit coordination program was found to be
satisfactory.
(2) Circuit Breaker / Protective Relay Maintenance and Testing
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Circuit breaker and protective relay maintenance and testing are reviewed to verify that the licensee has an established
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program to ensure circuit coordination is maintained.
The licensee performs relay testing and maintenance at 24 month intervals.
Circuit breakers are tested and maintained at
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36 month intervals.
Breaker and relay maintenance and testing are scheduled by an automated work order program.
Maintenance records for the following randomly selected circuit breakers or protective relays were reviewed to verify that maintenance and testing were being performed at the specified frequency:
Component Title Frequency Dates
1A52 Post Incident Room Heater 36 Months 8/86 Breaker 7/8/83 1A57 Control Rod Drive Pump 1 36 Months 10/21/86
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Breaker 5/31/83 1C15 Service Water Pump 1 36 Months 10/22/86 Breaker 6/22/83
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K76X 125 VDC D-3 Overcurrent 24 Months 10/9/85 Relay 6/8/83
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K59X Emergency Generator 24 Months 11/2/85 Overcurrent Auxiliary 6/7/83
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maintenance intervals.
The licensee's practice of adjusting breaker and relay testing and maintenance to coincide with refueling outages was acceptable.
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(3) High Impedance Fault Analysis The high impedance fault concern occurs when multiple high impedance faults exist as loads on a safe shutdown power supply and cause the loss of the safe shutdown power supply prior to the high impedance faults clearing.
In the event that safe shutdown power supplies are lost from fire induced high impedance faults, the licensee has provided procedural guidance (0NP-2.36, Revision 118, Loss Of Station Power and EMP-3.1, Revision 56, Loss of DC Power System) to strip bus / panel loads and reenergize only loads needed to achieve safe shutdown.
The licensee's procedures to manually isolate high impedance faults provide protection for the high impedance fault concern.
The licensee's protection for high impedance faults was found to be satisfactory, b.
Spurious Signals The spurious signal concern is made up of two items:
The false motor, control, and instrument readings such as
occurred at the 1975 Brown's Ferry fire.
These could be caused by fire initiated grounds, shorts or open circuits.
Spurious operation of safety-related or non safety-related
components that would adversely affect shutdown capability (e.g. RHR/RCS isolation valves).
(1) High/ Low Pressure Interfaces High/ low pressure interfaces are examined to determine if the licensee has provided protection to prevent fire induced spurious signals from producing a fire induced Loss Of Coolant Accident (LOCA).
NRC guidance for protecting high/ low pressure interfaces includes:
Multiple (unlimited) hot short circuits, open circuits and
short circuits to ground are credible (The single spurious signal criteria does not apply).
Three phase hot short circuits are credible.
credible.
The above guidance was employed to review for the high/ low pressure interface spurious signal concern during this inspection.
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components that form a high/ low pressure boundary:
M0-7050, Main Steam Isolation Valve,
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M0-7067, Turbine Bypass Isolation Valve, and
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the interface components is maintained closed.
Since M0-7067, Turbine Bypass Isolation Valve, and M0-7050, Main Steam Isolation Valve, are normally open valves,
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spurious opening of CV-4014, Turbine Bypass Valve was l
examined.
CV-4014 will open when 120 VAC is applied to SV-4932A via cable C02-Z03/19 or SV-49328 via C02-Z03/19A.
Cables C02-Z03/19 and C02-ZO3/19A are routed in common enclosure in Fire Area 5, Electrical Equipment Room, in l
trays VB09, DC01, AC01, and AD02.
Tray VB09 contains i
120VAC cables CO2-Y01/8 and CO2-Y01/11 which could cause i
spurious opening of CV-4014 and present a high/ low pressure interface concern in the event of fire in Fire Area 5.
Cable C01-C02/7 for M0-7050, Main Steam Isolation Valve,
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Cable routing for cables associated with M0-7067, Turbine Bypass Isolation Valve, could not be determined (the cab'ie routing documentation listed field routing for all M0-7067 cables); therefore, M0-7067 cables were assumed to have routings similar to CV-4014 and M0-7050 through Fire Area 5.
The licensee has provided alternate shutdown capability for Fire Area 5 which includes the capability to isolate M0-7050 normal circuits and shut M0-7050 from the ASB.
The licensee's control of the Turbine Bypass High/ Low Pressure Interface was found to be satisfactory.
(b) Main Steam Drain High/ Low Pressure Interface The Main Steam Drain Interface includes the following components that form a high/ low pressure boundary:
M0-7065, Main Steam Drain Isolation Valve, and
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the interface components is maintained closed.
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CV-4107, operated by SV-4917,'has been failed in the closed position.
The power cable to SV-4917, Z06-Z07/1, is routed via conduits A285, A286, A295, and A287 which will protect against hot shorts.
Additionally, cable 206-Z07/1 has been disconnected at SV-4917 for EEQ reasons (Modification SC-85-017) to ensure that CV-4107 remains shut.
Since the licensee is taking Appendix R credit for i
CV-4107 being failed shut, it would be appropriate for the licensee to document the Appendix R purpose in addition to
- I the EEQ purpose on Big Rock Point controlled drawings.
The licensee's control of the Main Steam Drain High/ Low Pressure Interface was found to oe satisfactory.
O)' Shutdown Cooling High/ Low Pressure Interface, The Shutdown Cooling Interface includes the following components that combine to form high/ low pressure boundaries:
M0-7056, Shutdown Cooling Isolation Valve,
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CV-4018, Shutdown System Drain Valve.
During normal operations the follcwing conditions exist:
By procedure M0-7056, M0-7058, M0-7057 and M0-7059
are closed with power removed, the breakers are tagged open CV-4017 and CV-4018 are open
In the above lineup, the Shutdown Cooling Interface is protected provided M0-7056 and M0-7058 remain shut.
In the Big Rock Point Safety Evaluation Report forwarded under NRC letter dated March 8, 1983, the NRC approved control of the Shutdown Cooling Interface by:
"The power for the redundant electrically controlled valves at the high/ low pressure interface of the snutdown cooling system will be disconnecteo prior to raising the pressure of the reactor coolant."
The licensee is in compliance with the March 8, 1983, Safety Evaluation Report, however, the inspectors raised a concern that the control of the shutdown cooling high/ low pressure interface needs to be further analyzed to determine that a fire induced LOCA will not occur.
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It appeared that although the licensee satisfied the SER method of control for high/ low pressure interfaces, the protection provided for multiple /3 phase hot shorts described in G.L. 86-10, Enclosure 2, Paragraph 5.3.1-is not provided.
The specific concern raised was removing power at the circuit breaker prevents hot shorts in the control circuitry but not in the power cable between the circuit breaker and the valve.
The following analysis describes the concern for protection of the Shutdown Cooling High/ Low Pressure Interface:
The above listed Shutdown cooling High/ Low Pressure Interface valves are the valves believed to have the potential to spuriously open under the following circuit failure conditions:
Component Cables Generic Letter 86-10 Failure Mode M0-7056 &
P26-R01/1 3 phase 480 V hot short M0-7058 or R01-R02/4 M0-7057 &
P26-R01/2 3 phase 480 V hot short M0-7059 or R01-R02/5 CV-4017 R01-Z01/1 120 V hot short CV-4018 R02-Z03/1 120 V hot short Based on the above description, the inspectors review of the licensee's cable routing documentation indicated that:
The above listed cables are routed in common enclosure in cable tray TF03 in Fire Area 11, Zone F, Containment - Shutdown Heat Exchanger Room,
Cables P26-R01/1 and P26-R02/2 are routed in common enclosure in trays TF01 and TF02 in Fire Area 11, Zone B, Containment - South of Reactor.
- Cables P26-R01/1 and P26-R01/2 are routed in common enclosure in trays SA03, SA04, and SA05 in Fire Area 11, Zone A, Containment - Interior Cable Penetration, Tray TF03 contains other 3 phase 480 V and 120 V
cables that could cause the required hot short conditions, and Trays SA03, SA04, SA05, TF01, and TF02 contain other
3 phase 480 V cables that could cause the required hot short conditions.
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The licensee's protection for fire induced spurious operation of high/ low pressure interfaces was found to be satisfactory.
Tne satisfactory evaluation is based on licensee compliance with the approved SER; however, licensee protection for high/ low pressure interfaces needs to be reviewed further for protection against multiple /3 phase hot shorts.
This is considered an open item (155/88006-07) pending licensee review of the above mentioned concerns.
(2) Isolation of Fire Instigated Spurious Signals l
The licensee has provided isolation for fire instigated spurious signals by various methods, including:
Administrative controls Isolation / Transfer switches (redundant fuses used)
Dedicated instruments
Cable relocation Manual component operation
The licensee's methods of fire instigated spurious signal isolation were found to be satisfactory.
The licensee's protection for the spurious signal associated circuit concern was found to be satisfactory, c.
Common Enclosure The common enclosure associated circuit concern is found when redundant circuits are routed together in a raceway or enclosure and they are not electrically protected, or fire can destroy both circuits due to inadequate fire protection means.
During the inspection, cable routing for the following redundant safe shutdown components were reviewed for common enclosure routing:
Fire Tray /
Area /
Conduit Ione Cable Typ_e Component Status TF03 11F P26-R01/1 POWER M0-7056 Refer to Paragraph 9.b(1)(c)
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R01-R02/4 POWER M0-7058 Refer to Paragraph 9.b(1)(c)
P26-R01/2 POWER MO-7057 Refer to Paragraph 9.b(1)(c)
R01-R02/5 POWER M0-7059 Refer to Paragraph 9.b(1)(c)
R01-Z01/1 POWER SV-4861/
Refer to Paragraph 9.b(1)(c)
CV-4017 R02-ZO3/1 POWER SV-4862/
Refer to Paragraph 9.b(1)(c)
CV-4018 TF01 11B P26-R01/1 POWER M0-7056 Refer to Paragraph 9 b(1)(c)
TF02 P26-R01/2 POWER M0-7057 Refer to Paragraph 9.b(1)(c)
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Fire Tray /
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Conduit Zone Cable Tyge Component Status SA03 11A P26-R01/1 POWER M0-7056 Refer to Paragraph 9.b(1)(c)
SA04 P26-R01/2 POWER M0-7057 Refer to Paragraph 9.b(1)(c)
SA05 VC01
C01-C02/80 CONTROL M0-7052 ALTERNATE SHUTDOWN USED FA02
/85 CONTROL CA01 C01-C02/79 CONTROL M0-7062 ALTERNATE SHUTDOWN USED EA03
/86 CONTROL VB03 C01-C02/77 CONTROL M0-7053 ALTERNATE SHUTDOWN USED C01-C02/78 CONTROL M0-7063 ALTERNATE SHUTDOWN USED VC02
C01-N01/6 CONTROL M0-7052 ALTERNATE SHUTDOWN USED FA02 C01-N01/7 CONTROL H0-7062 ALTERNATE SHUTDOWN USED C01-C30/1 CONTROL M0-7053 ALTERNATE SHUTDOWN USED C01-C30/1 CONTROL M0-7063 ALTERNATE SHUTDOWN USED TB335 21G C02-N01/20 CONTROL M0-7052 RDS CORE SPRAY METHOD II USED C02-N01/21 CONTROL M0-7062 RDS CORE SPRAY METHOD II USED N01-R01/39 POWER M0-7053 RDS CORE SPRAY METHOD II USED
/41 POWER M0-7053
/42 POWER M0-7053 N01-R01/42 POWER M0-7063 RDS CORE SPRAY METHOD II USED
/43 POWER M0-7063
/44 POWER M0-7063 H115 11N CO2-N01/20 CONTROL M0-7052 RDS CORE SPRAY METHOD II USED TB336 CO2-N01/21 CONTROL MO-7062 RDS CORE SPRAY METHOD II USED N01-R01/39 POWER M0-7053 RDS CORE SPRAY METHOD II USED
/40 POWER M0-7053
/41 POWER M0-7053 N01-R01/42 POWER M0-7063 RDS CORE SPRAY METHOD II USED
/43 POWER M0-7063
/44 POWER M0-7063 JB88 11H CO2-N01/20 CONTROL M0-7052 RDS CORE SPRAY METHOD IV.3 USED C01-N01/6 CONTROL M0-7052 P26-N01/6 POWER M0-7052 CO2-N01/21 CONTROL M0-7062 RDS CORE SPRAY METHOD IV.3 USED C01-N01/7 CONTROL M0-7062 P26-N01/7 POWER M0-7062 N01-R01/39 POWER M0-7053 RDS CORE SPRAY METHOD IV.3 USED
/40 POWER M0-7053
/41 POWER M0-7053 N01-R01/42 POWER MO-7063 RDS CORE SPRAY METHOD IV.3 USED
/43 POWER M0-7063
/44 POWER M0-7063
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Area /
Conduit Zone Cable Tyy_e Component Status EA01
C02-Z07/6 INSTRUMENT LT-IA39 ALTERNATE SHUTDOWN USED C02-M(H29)18 INSTRUMENT LT-RE20A ALTERNATE SHUTDOWN USED C02-M(H49)13 INSTRUMENT LT-RE20A AA01
C02-Z07/6 -
INSTRUMENT LT-IA39 ALTERNATE SHUTDOWN USED
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CO2-M(H49)18 INSTRUMENT LT-RE20A ALTERNATE SHUTDOWN USED CO2 M(H49)13 INSTRUMENT LT-RE20A The licensee's protection for the common enclosure associated circuit
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concern was found to be satisfactory.
10.
Comunications The prime means of comunication to implement EMP 3.10 is the two-way radio system.
A test was performed between the ASB and the Control Room.
The results were satisfactory, although the licensee stated that comunication between the Containment and the ASB was usually only possible by stepping outside the ASB.
The actions inside containment are those necessary to achieve cold shutdown, would occur several hours into the fire scenario, and do not absolutely require radio communication.
This was considered acceptable.
However, since the radio system requires charging after approximately
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eight hours, and the plant may still be in hot shutdown at that time when
comunications may still be required, the licensee was asked to show that the radio system could be inaintainad charged and available for the entire
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time needed.
This is considered an w n item (155/88006-08) pending licensee action to resolve the above concem, 11.
Exemption Review During this inspection, the inspectors continued to review licensee compliance with granted NRC exemption requests which had been initiated
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during the previous Appendix R (1985/1986) inspection.
But, due in part to the lack of a clear pr sentable FPPSD, this review was not completed.
.i By letter dated February 27, 1987, the licensee submitted an improved FPPSD.
During this inspection, licensee compliance with the granted exemptions was reviewed.
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March 8, 1987 SER
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The inspectors verified licensee conformance with the following portions of the granted exemption, dated March 8, 1983:
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(1) E,xemption 1 The exemption approved hot shutdown repair of the Control Rod Drive Pumps and required the licensee to:
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Store the necessary replacemeret cables on site Cut the cables to the appropriate size and fit the cables
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with plug-in connectors to facilitate a quick repair
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Preplan the repairs to allow them to be performed within
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a 9 hour1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />. time span The licensee was found to be in compliance with the SER exemption in that the licensee had modified the plant to
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provide power to Control Rod Drive Pump 1 without having to perform hot shutdown repairs.
Specifically:
Alternate power is available via Control Rod Drive Pump
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Transfer Switch (TRS-1442)
Redundant fusing is provided in the alternate power
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circuit EMP-3.10 - FIRE, provides procedural instructions for
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supplying alternate power to Control Rod Drive Pump 1 (2) Exemption 3 The exemption required the licensee to protect one emergency condenser inlet valve with a non-combustible radiant energy shield.
A sheet metal radiant energy shield was verified to be installed between the redundant emergency condenser inlet valves.
In addition, as committed to by the Plant Superintendent by letter dated July 18, 1986, the inspectors determined that the control of combustibles on the emergency condenser deck was being maintained satisfactorily.
(3) Exemption 4 (Containment)
The exemption required installation of alternate power to the emergency condenser outlet valves.
Alternate power to the emergency condenser outlet valves was verified to be installed.
Specifically:
M0-7053, Emergency Condenser Outlet Valve - alternate power
is supplied via redundant fuses through Transfer Switch, TRS-6602 M0-7063, Emergency Condenser Outlet Valve - alternate power
is supplied via redundant fuses through Transfer Switch, TRS-6603
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- Transfer Switches TRS-6602 and TRS-6603 - installed in i
the Alternate Shutdown Building
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- ' EMP-3.10 - FIRE provides procedural instructions for supplying alternate power to the Emergency Condenser
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Since the previous Appendix R inspection review did not identify any other concerns with the exception of those concerns remaining open, as discussed in Paragraph 2.f of this report, the review to determine licensee compliance with the approved exemption, dated March 8, 1983, is considered complete at this time, b.
March 26, 1985 SER The inspectors also verified licensee conformance with the following portion of the exemption, granted on March 26, 1985:
The exemption requires that redundant RDS and EC cables be routed in conduit on the south face of the steam drum enclosure wall.
The redundant RDS and EC cables were verified to be routed in conduit on the south face of the steam drum enclosure wall.
The inspectors also confirmed that no transient combustibles were located in the vicinity of the redundant RDS and EC cables routed on the south face of the steam drum enclosure wall.
Since the previous Appendix R inspection did not identify any other concerns relative to the steam drum enclosure wall exemption request, the review to determine licensee compliance with the approved exemption, dated March 16, 1985, is considered complete at this time.
12.
Open Item Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, or which involve some action on the part of the NRC or licensee or both.
Open items disclosed during the inspection area discussed in paragraphs 7, 8, 9 and 10 of this report.
13.
Unresolved Item Aq unresolved item is a matter about which more information is required in order to ascertain whether it is an acceptable item, a violation, a
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failure to meet a licensee commitment, or a deviation. Three unresolved items disclosed during the inspection are discussed in Paragraphs 2.f and 6 of the report.
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Exit Interview The inspector met with licensee representatives (denoted in Paragraph 1)
at the conclusion of the inspection on March 25, 1988, and summarized the j
scope and findings of the inspection.
hie inspector also discussed the likely informational content of the inspection report with regard to documents reviewed by the inspector during the inspection.
The licensee did not identify any of the documents as proprietary.
On May 3, 1988, additional discussions relating to the inspection were held between l
menbers of the licensee's staff and the inspector.
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